Water-based drilling fluids using latex additives

ABSTRACT

A water-based drilling fluid having a polymer latex capable of providing a deformable latex film on at least a portion of a subterranean formation has been discovered to provide reduced drilling fluid pressure invasion when used to drill in shale formations for hydrocarbon recovery operations. A precipitating agent such as a silicate or an aluminum complex (e.g. sodium aluminate) is preferably used in conjunction with the polymer. Typically, the water present contains a salt to form a brine, often to saturation, although the invention may be practiced with fresh water. If a salt is employed, it is often helpful to additionally employ a surfactant, such as a betaine, for example.

CROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application is a continuation in part of U.S. patentapplication Ser. No. 09/785,842 filed on Feb. 16, 2001.

FIELD OF THE INVENTION

[0002] The present invention relates to water-based drilling fluids usedduring petroleum recovery operations, and more particularly relates, inone embodiment, to using water-based drilling fluids containingadditives to inhibit penetration of the borehole wall by the fluid.

BACKGROUND OF THE INVENTION

[0003] Drilling fluids used in the drilling of subterranean oil and gaswells as well as other drilling fluid applications and drillingprocedures are known. In rotary drilling there are a variety offunctions and characteristics that are expected of drilling fluids, alsoknown as drilling muds, or simply “muds”. The drilling fluid is expectedto carry cuttings up from beneath the bit, transport them up theannulus, and allow their separation at the surface while at the sametime the rotary bit is cooled and cleaned. A drilling mud is alsointended to reduce friction between the drill string and the sides ofthe hole while maintaining the stability of uncased sections of theborehole. The drilling fluid is formulated to prevent unwanted influxesof formation fluids from permeable rocks penetrated and also often toform a thin, low permeability filter cake which temporarily seals pores,other openings and formations penetrated by the bit. The drilling fluidmay also be used to collect and interpret information available fromdrill cuttings, cores and electrical logs. It will be appreciated thatwithin the scope of the claimed invention herein, the term “drillingfluid” also encompasses “drill-in fluids”.

[0004] Drilling fluids are typically classified according to their basematerial. In water-based muds, solid particles are suspended in water orbrine. Oil can be emulsified in the water or brine. Nonetheless, thewater is the continuous phase. Oil-based muds are the opposite. Solidparticles are suspended in oil and water or brine is emulsified in theoil and therefore the oil is the continuous phase. Oil-based muds thatare water-in-oil emulsions are also called invert emulsions. Brine-baseddrilling fluids, of course are a water-based mud in which the aqueouscomponent is brine.

[0005] Optimizing high performance water base mud design is commonly atthe forefront of many drilling fluid service and oil operatingcompanies' needs due to the various limitations of invert emulsionfluids. Invert emulsion fluids formulated with traditional diesel,mineral or the newer synthetic oils are the highest performing drillingfluids with regard to shale inhibition, borehole stability, andlubricity. Various limitations of these fluids, however, such asenvironmental concerns, economics, lost circulation tendencies, kickdetection, and geologic evaluation concerns maintains a strong marketfor high performance water based fluids. Increased environmentalconcerns and liabilities continue to create an industry need for waterbased drilling fluids to supplement or replace the performance leadinginvert emulsion mud performance.

[0006] A particular problem when drilling into shale formations withwater-based fluids is the pore pressure increase and swelling frompenetration of the shale by the fluid. Shale stabilizers are typicallyadded to the mud to inhibit these phenomena and to stabilize the shalefrom being affected by the mud.

[0007] Reducing drilling fluid pressure invasion into the wall of aborehole is one of the most important factors in maintaining wellborestability. It is recognized that sufficient borehole pressure willstabilize shales to maintain the integrity of the borehole. When mud orliquid invades the shale, the pressure in the pores rises and thepressure differential between the mud column and the shale falls. Withthe drop in differential pressure, the shale is no longer supported andcan easily break off and fall into the well bore. Likewise, the invasionof water into the shale matrix increases hydration or wetting of thepartially dehydrated shale body causing it to soften and to lose itsstructural strength. Chemical reactivity can also lead to instability.There is always a need for a better composition and method to stabilizethe shale formations.

[0008] In the drilling of depleted sands, there is also a need toprevent of intrusion of drilling fluid through the borehole and into theformation. Rather than concern for formation stability, the loss ofdrilling fluid and resulting higher production costs are the morecommonly the main concern. It would be desirable to be able to reducethe loss of drilling fluid into depleted sands.

[0009] It is apparent to those selecting or using a drilling fluid foroil and/or gas exploration that an essential component of a selectedfluid is that it be properly balanced to achieve all of the necessarycharacteristics for the specific end application. Because the drillingfluids are called upon to do a number of tasks simultaneously, thisdesirable balance is difficult to achieve.

[0010] It would be desirable if compositions and methods could bedevised to aid and improve the ability of drilling fluids tosimultaneously accomplish these tasks.

SUMMARY OF THE INVENTION

[0011] Accordingly, it is an object of the present invention to providemethods to stabilize shale formations and avoid loss of fluids intodepleted sands formations when drilling with water-based drillingfluids.

[0012] It is another object of the present invention to providewater-based drilling fluids that reduce the rate of drilling fluidpressure invasion into the borehole wall.

[0013] Still another object of the invention is to provide a compositionand method that increase the pressure blockage, reliability, magnitude,and pore size that can be blocked with water-based fluids forstabilizing shale formations.

[0014] In carrying out these and other objects of the invention; thereis provided, in one form, a water-based drilling fluid including waterand a polymer latex capable of providing a deformable latex film or sealon at least a portion of a subterranean formation.

BRIEF DESCRIPTION OF THE DRAWINGS

[0015]FIG. 1 shows a chart of the formation pressure as a function oftime for a pressure invasion test using various intermediate testformulations;

[0016]FIG. 2 is a graph of the surfactant effect on GENCAL 7463 particlesize in 20% NaCl/1 lb/bbl (2.86 g/l) NEWDRILL PLUS/1 lb/bbl (2.86 g/l)XAN-PLEX D/0.5 lb/bbl (1.43 g/l) sodium gluconate/3 lb/bbl (8.58 g/l)NaAlO2/5% by volume GENCAL 7463;

[0017]FIG. 3 is a graph of the influence of polymer resins (3 lb/bbl,8.58 g/l) on GENCAL 7463 particle size distributions after 16 hours,150° F. (66° C.) hot roll in 20% NaCl/0.75 lb/bbl (2.15 g/l) XAN-PLEXD/0.5 lb/bbl (1.43 g/l) sodium D-gluconate/0.4 lb/bbl (1.14 g/l)NEW-DRILL PLUS/2 lb/bbl (5.72 g/l) BIO-PAQ/3 lb/bbl (8.58 g/l) NaAlO₂/3%GENCAL 7463/1 lb/bbl (2.86 g/l) EXP-152;

[0018]FIG. 4 is a graphical comparison of the effects on mud propertiesfor EXP-154 versus ALPLEX in 12 lb/gal (1.44 kg/l) mud; the base mud was20% NaCl/0.5 lb/bbl (1.43 g/l) XAN-PLEX D/2 lb/bbl (5.72 g/l) BIO-LOSE/1lb/bbl (2.86 g/l) NEW-DRILL PLUS/3% EXP-155/150 lb/bbl (429 g/l)MIL-BAR/27 lb/bbl (77.2 g/l) Rev Dust;

[0019]FIG. 5 is a graph of PPT test results for ALPLEX, EXP-154/EXP-155,and ISO-TEQ fluids;

[0020]FIG. 6 is a graph showing the effect of circulation onEXP-154/EXP-155 mud performance;

[0021]FIG. 7 is a graph showing the effect of latex on mud properties in9.6 lb/gal (1.15 kg/l) 20% NaCl fluid after 16 hours, 250° F. (121° C.)hot roll; the base fluid was 20% NaCl/1 lb/bbl (2.86 g/l) XAN-PLEX D/0.4lb/bbl (1.14 g/l) NEW-DRILL PLUS/2 lb/bbl (5.72 g/l) BIO-PAQ/5 lb/bbl(14.3 g/l) EXP-154/10 lb/bbl (28.6 g/l) MIL-CARB/27 lb/bbl (77.2 g/l)Rev Dust;

[0022]FIG. 8 is a graph showing the effect of latex on mud properties in12 lb/gal (1.44 kg/l) after hot rolling for 16 hours at 250° F. (121°C.); the base fluid was 20% NaCl/0.75 lb/bbl (2.15 g/l) XAN-PLEX D/0.4lb/bbl (1.14 g/l) NEW-DRILL PLUS/3 lb/bbl (8.58 g/l) BIO-PAQ/5 lb/bbl(14.3 g/l) EXP-154/150 lb/bbl (429 g/l) MIL-CARB/27 lb/bbl (77.2 g/l)Rev Dust;

[0023]FIG. 9 is a graph of 96 hour Mysidopsis bahia range-finder resultsfor experimental products in 12 lb/gal (1.44 kg/l) fluids where the basefluid is 20% NaCl/0.5 lb/bbl (1.43 g/l) XAN-PLEX D/0.4-1 lb/bbl(1.14-2.86 g/l) NEW-DRILL PLUS/2 lb/bbl (5.72 g/l) MIL-PAC LV (orBIO-PAQ)/150 lb/bbl (429 g/l) MIL-BAR;

[0024]FIG. 10 is a graph of high temperature high pressure (HTHP) fluidloss rate on 50 mD cement disk for the mud containing 3% latex polymerafter being hot rolled at 250° F. for 16 hours; and

[0025]FIG. 11 is a photograph of an internal filter cake formed usingthe method of the present invention.

DETAIL D D SCRIPTION F THE INVENTION

[0026] It has been discovered that a polymer latex added to awater-based drilling fluid can reduce the rate the drilling fluidpressure invades the borehole wall of a subterranean formation duringdrilling. The polymer latex preferably is capable of providing adeformable latex film or seal on at least a portion of a subterraneanformation. Within the context of this invention, the terms “film” or“seal” are not intended to mean a completely impermeable layer. The sealis considered to be semi-permeable, but nevertheless at least partiallyblocking of fluid transmission sufficient to result in a greatimprovement in osmotic efficiency. In a specific, non-limitingembodiment, a submicron polymer latex added to a high salt water-basedmud containing an optional, but preferred combining/precipitating agent,such as an aluminum complex will substantially reduce the rate of mudpressure penetration into shale formations. The pressure blockage,reliability, magnitude and pore size that can be blocked are allincreased by the latex addition. Inhibiting drilling fluid pressureinvasion into the wall of a borehole is one of the most importantfactors in maintaining wellbore stability.

[0027] The essential components of the water-based drilling fluids ofthis invention are the polymer latex and water, which makes up the bulkof the fluid. Of course, a number of other common drilling fluidadditives may be employed as well to help balance the properties andtasks of the fluid.

[0028] The polymer latex is preferably, but not limited to acarboxylated styrene/butadiene copolymer or a sulfonatedstyrene/butadiene copolymer. A particular, non-limiting carboxylatedstyrene/butadiene copolymer is GENCAL 7463 available from OmnovaSolution Inc. A particular, non-limiting sulfonated styrene/butadienecopolymer is GENCEAL 8100 also available from Omnova Solution Inc. Othersuitable polymer latexes include, but are not limited to polymethylmethacrylate, polyethylene, polyvinylacetate copolymer, polyvinylacetate/vinyl chloride/ethylene copolymer, polyvinyl acetate/ethylenecopolymer, natural latex, polyisoprene, polydimethylsiloxane, andmixtures thereof. A somewhat less preferred polymer latex ispolyvinylacetate copolymer latex, more specifically, an ethylenevinylchloride vinylacetate copolymer. While polyvinylacetate copolymerlatices will perform within the methods of this invention, theygenerally do not perform as well as the carboxylated styrene/butadienecopolymers. The average particle size of the polymer latex is preferablyless than 1 micron or submicron and most preferably having a diameter ofabout 0.2 microns or 0.2 microns or less. Other polymers in the dispersephase may be found to work. It is anticipated that more than one type ofpolymer latex may be used simultaneously. The proportion of the polymerlatex in the drilling mud, based on the total amount of the fluid mayrange from about 0.1 to about 10 vol. %, preferably from about 1 toabout 8 vol. %, and most preferably from about 2 to about 5 vol. %.

[0029] The sulfonated latexes of the present invention have an addedadvantage in that they can often be used in the absence of a surfactant.This can simplify the formulation and transportation of the drillingfluid additives to production sites. This can also reduce costs in someapplications. In applications of drilling in depleted sands, there isoften no need of a precipitating agent. In the depleted sandsapplications, there is also often no need of a surfactant forcarboxylated styrene/butadiene copolymers for fresh water applications.

[0030] The optional salt may be any common salt used in brine-baseddrilling fluids, including, but not necessarily limited to calciumchloride, sodium chloride, potassium chloride, magnesium chloride,calcium bromide, sodium bromide, potassium bromide, calcium nitrate,sodium formate, potassium formate, cesium formate and mixtures thereof.By a “high salt content” is meant at least 20 weight percent, andsaturated brine solutions are preferred in one non-limiting embodiment.It will appreciated that it is impossible to predict in advance what thesalt content of a particular saturated brine solution will be since thesaturation point depends on a number of factors including, but notlimited to the kinds and proportions of the various components of thewater-based fluid. The salt is optional because the invention willperform without it, that is, using fresh water.

[0031] Another optional component is precipitating agent. Suitableprecipitating agents include, but are not limited to, silicates,aluminum complexes, and mixtures thereof. Suitable aluminum complexesinclude, but are not limited to, sodium aluminate, NaAl₂O₂, sometimeswritten as Na₂OAl₂O₃, aluminum hydroxide, aluminum sulfate, aluminumacetate, aluminum nitrate, potassium aluminate, and the like, andmixtures thereof (especially at pH of >9 for these compounds to besoluble in water). The proportion of the precipitating agent in thedrilling mud, based on the total amount of the fluid may range fromabout 0.25 to about 20 lb/bbl (about 0.71 to about 57.2 g/l), preferablyfrom about 1 to about 10 lb/bbl (about 2.86 to about 28.6 g/l) and mostpreferably from about 2 to about 7 lb/bbl (about 5.72 to about 20 g/l).Without being limited to a particular theory, the precipitating agent isbelieved to chemically bound to the surface of the clay of the boreholeand provide a highly active polar surface.

[0032] Another optional component of the composition of the invention isa surfactant. If the surfactant is present, the surfactant treated latexwets the surface strongly and accumulates to form a film or coating thatseals fractures and defects in the shale. Suitable wetting surfactantsinclude, but are not limited to, betaines, alkali metal alkyleneacetates, sultaines, ether carboxylates, and mixtures thereof. It hasbeen determined that surfactants are particularly beneficial when saltsare present in the drilling fluid, and are not as preferred in freshwater fluid systems.

[0033] The proportions of these components based on the totalwater-based drilling fluid are from about 0.1 to 10 volume % of polymerlatex, at least 1 wt % of salt (if present), from about 0.25 to 20lb/bbl (about 0.71 to about 57.2 g/l) of precipitating agent (ifpresent), from about 0.005 to about 2 vol. % of surfactant (if present),the balance being water. In a more preferred embodiment, the proportionsrange from about 1 to 8 vol. % of polymer latex, at least 1 wt % of salt(if present), from about 1 to 10 lb/bbl (about 2.86 to about 28.6 g/l)of precipitating agent (if present) from about 0.01 to about 1.75 vol. %of wetting surfactant (if present), the balance being water.

[0034] It is desired that the sodium aluminate or other precipitatingagent be in a metastable form in the mud, which means that it is insuspension or solution, but precipitates out upon the borehole wall.Typically, aluminum compounds have been added to the mud on site. Ifadded to mud formulations earlier, they tend to be unstable andprecipitate prematurely.

[0035] Since the development of pore pressure transmission (PPT)testing, the effects of various chemical additives on pore pressuretransmission rates have been evaluated. Testing has focused primarily onthe performance of salts, glycols, and precipitating agents such assilicates and aluminum complexes. Improvements in PPT test equipment andmethods have accompanied the general interest and search for increasingmore efficient water-based mud systems that approach the PPT testperformance of invert emulsion fluids. While other investigators havefound silicate fluids to be especially effective for reduced poorpressure transmission rates, silicate fluids have not been widely useddue to limitations of these fluids. Although lower pore pressuretransmission rates have been demonstrated for salts, glycols, andaluminum complexing agents, these products still do not approach theperformance of invert emulsion fluids.

[0036] A combination of a new formulation approach as well asmodification to the PPT test procedure was used to demonstrate theefficacy of an alternative approach to enhance the performance ofwater-based mud systems. Water-dispersible polymers were selected toprovide sources of small, deformable particles to provide a sealing andblocking effect on the shale. The first of these polymers was tested onthe PPT test in a fluid with other products.

[0037] The invention will be further illustrated with respect to thefollowing examples, which are only meant to further illuminate theinvention, and not limit it in any way.

EXAMPLE1 Fluid Intermediate Preparation

[0038] The following Example is the first preparation of theintermediate compositions of this invention. Unless otherwise noted, thelatex in the Examples is 728 Latex, a polyvinylacetate latex. Grams perbarrel Grams per 7 barrels Component (per 159 l) (per 1,113 l) Tap water310 2170 Sodium aluminate 2  14 LIGCO 2  14 AIRFLEX 728 10.5  73.5 (75cc) The mixture was hot rolled. After 6 days, the pH was 11.51. Thebottom of the jar was about 75% covered with {fraction (1/32)}″ (0.79mm) fines. The following components were then added, again given in gramproportions for a single barrel and 7 barrels, respectively: NEWDRILLPLUS 0.4   2.8 NaCl (20%) 77.5  540 MILPAC LV 2  14

EXAMPLE 2 Shale Pressure Penetration Determination

[0039] The pore pressure transmission (PPT) device is based on a 1500psi (10,300 kPa) Hassler cell designed for 2.5 cm diameter core plugsfrom 2.5 cm to 7.5 cm in length. A Hassler cell is a cylinder with apiston inserted in each end. The core is held between the two pistons. Arubber sleeve is placed around the core and the pistons to seal aroundthe core and prevent flow around the core. The outside of the sleeve ispressured to make a good seal. These tests use a core 25 mm in diameterand 25 mm long.

[0040] The low pressure side of the core (formation side) is fitted witha 1 liter, 2000 psi. (13,800 kPa), stainless steel accumulator toprovide back pressure. The high pressure side of the core is connectedto two similar accumulators, one for pore fluid, and one for the testfluid. The pressure in each accumulator is controlled with a manualregulator fed by a 2200 psi (15,200 kPa) nitrogen bottle.

[0041] All pressures are monitored with Heise transducers. Thetransducer pressures are automatically computer logged at presetintervals.

[0042] The cell is enclosed in an insulated chamber and the temperaturemaintained with a 200 watt heater. The heater is controlled with a Dwyertemperature controller driving a Control Concepts phase angle SCRcontrol unit. Temperature control is accurate to +/−0.05° C.

[0043] A pressure is applied to one end of the core and the flow throughthe core is measured. The piston on the low pressure side is filled withliquid, and blocked, so an increase in liquid pressure is measuredrather than flow. A very small amount of liquid flow through the corewill make a large rise in the pressure, making the cell sensitive enoughto measure flow through shale. Shale has a very low permeability, so theflow of fluid through it is very small. Pressure is plotted versus time.Results are expressed as formation pressure (FP). If the FP increasesovertime, there is pressure penetration; if the formation pressuredecreases over time there is not, and the latter is what is desired. Thefluid of Example 1 was used. Three 50% displacements of 50 cc each wereperformed during and just after heating up of the test cell. One run wasstarted at 100% displacement and the temperature was difficult tocontrol, so it was decided starting at 50% was better.

[0044] Temperature=155° F. (68.3° C.)

[0045] Borehole side pressure=250 psi (1,720 kPa)

[0046] Confining pressure=370 psi (2,550 kPa) Formation Pressure Time,hours:minutes psi kPa 0   48.1 332 1:30 47.9 330 2:00 47.6 328 7:15 50.9359

[0047] Eventually, 50 cc of fluid was displaced up to 50% within 2° F.(1.1° C.) temperature variation. The pressure rose to 52.7 psi (363kPa). Formation heat was turned off, and the temperature was 147° F.(64° C.). Displacement pulled the formation pressure down to 36 psi (248kPa), then rose to 80.2 (553 kPa) over the next two days. The initialformation pressure decrease demonstrated that the formulation of theinvention inhibited pressure penetration.

EXAMPLE 3 Fluid Interm diate Pr paration—Pr p rti ns in Grams Unl ss Othrwise Noted

[0048] Component Per barrel (per 159 l) Per 7 barrels (per 1,113 l) Tapwater 310 2170 cc Sodium aluminate 2  14 LIGCO 2  14 AIRFLEX 728 10.5 75 cc Latex NEWDRILL PLUS 0.4   2.8 NaCl (20%) 77.5  540 MILPAC LV 2 14

[0049] The sodium aluminate and AIRFLEX728 latex were mixed together andallowed to stand over the weekend. The mixture was then hot rolled at150° F. (66° C.) for two hours. The salt and polymers were then added.The sequence of addition to the sodium aluminate/latex mixture was: PHPA(partially hydrolyzed polyacrylamide; NEWDRILL PLUS), followed bymixing; then half of the salt, followed by MILPAC LV, followed by theother half of the salt. The mixture was hot rolled overnight.

EXAMPLE 4 Shale Pressure Penetration Determination

[0050] Borehole side pressure=250 psi (1,720 kPa)

[0051] Confining pressure=370 psi (2,550 kPa) Formation Pressure Time,hours:minutes psi kPa 0   46.3 319  5:49 2.3 16  7:36 0.6* 41 50:00 65.0448

EXAMPLES 5 and 6, COMPARATIVE EXAMPLES A-F

[0052] Two other inventive formulations (Examples 5 and 6) and sixcomparative Examples (A-F) were prepared and tested. The results areshown in FIG. 1. As indicated the Inventive Examples 5 and 6 both gavethe desired results of decreasing formation pressure over time. Thecomparative Examples undesirably gave increasing formation pressuresover time. The composition identities are given on FIG. 1 itself. Thedesignation “CORE: P2 PARALLEL” refers to the core being Pierre Shale inparallel orientation.

[0053] These results verify the necessity of having all threecomponents: the salt, the latex, and the sodium aluminate (Examples 5and 6). Use of the latex alone (comparative Ex. A), use of salt only(comparative Ex. B), use of the latex together with salt only(comparative Example C), use of sodium aluminate and the salt only(comparative Ex. D), use of the sodium aluminate and salt only(comparative Ex. E), and use of the sodium aluminate with salt only(comparative Ex. F) were all found to be ineffective, or at leastcertainly not as effective as the inventive composition.

[0054] Further experimental evidence indicates that some latex productsexhibit a synergistic effect with aluminum complexes that results inimproved pore pressure transmission characteristics. Stable drillingfluid systems have been formulated with latex that remain dispersed andflexible in highly saline (high salt content) fluids. Inventive drillingfluids provide pore pressure transmission performance closer tooil-based fluids than what is exhibited by current aluminum-baseddrilling fluids. Two features of this system are believed to be the maincontributors to shale stabilization. First, the ultra-fine, deformablelatex particles (having a preferable diameter of about 0.2 microns)mechanically seal shale micro-fractures and physically prevent furtherintrusion of drilling fluids into sensitive shale zones. Secondly, latexco-precipitation with precipitating agents, if present, such as aluminumcomplexes, produces a semi-permeable membrane on shale surfaces thatchemically improves the osmotic efficiency between the fluid and theborehole.

[0055] Three experimental additives were discovered for the inventivefluids: EXP-153, EXP-154 and EXP-155. EXP-153 is a sulfonated polymerresin used to control HTHP fluid loss in this system. EXP-154 isconsidered an alternative to aluminum complex product ALPLEX. Comparedto ALPLEX, EXP-154 exhibits much better compatibility with latex fluids.EXP-155 is a modified latex product. Compared to other commerciallyavailable latices EXP-155 displays less sensitivity to electrolytes anddoes not flocculate in 20% sodium chloride fluids at temperatures up to300° F. (149° C.). Furthermore, due to the wide temperature rangebetween its glass transition temperature (T_(g)) and melting point(T_(m)), the particles of EXP-155 remain deformable and capable ofplugging shale micro-fractures at most application temperatures. Thetoxicities of all of these products meet the requirement for fluiddisposal in the Gulf of Mexico.

[0056] Formulations and Fluid Properties

[0057] All fluids were mixed according to established Baker Hughes INTEQmixing procedures. The initial and final Bingham Plastic rheologicalproperties of plastic viscosity, yield point, ten second gels, and tenminute gels were measured by Fann 35 viscometer at 120° F. (49° C.). Theinitial and final pH and API filtrate were recorded. HTHP fluid loss at250° F. (121° C.) was measured after static and dynamic aging for 16hours at 250° F. (121° C.).

[0058] Latex Stability

[0059] The stability of the latex samples were first evaluated in 20%and 26% NaCl solutions by the following procedure:

[0060] 1. Add 332 ml 20% (or 26%) NaCl water solution into a mixer cupand start mixing.

[0061] 2. Slowly add 18 ml tested latex sample into the solution andadjust the Prince Castle mixer to 4000 rpm with Variac and tachometer.

[0062] 3. After stirring 5 minutes, slowly add 3 grams NaAlO₂ into theabove solution and mix for a total of 20 minutes. During the mixingperiod it may be necessary to add about 5 drops defoamer (LD-8) iffoaming is observed.

[0063] 4. Put this fluid into a jar and statically age for 16 hours at150° F. (66° C.).

[0064] 5. Remove the jar from the oven and cool to room temperature.Observe the fluid for flocculation and separation.

[0065] 6. If there is no separation or flocculation, sieve the fluidwith a 100-mesh (0.150 mm) screen. Observe sieve for amount of retainedlatex particles.

[0066] Additional evaluations were performed only for those sampleshaving passed the above screening test. A Malvern Mastersizer ParticleSize Analyzer was used to measure the particles size distributions oflatex in formulated fluids. The small sample dispersion unit and thestandard refractive index 50HD (Particle R.I.=1.5295, 0.1000 andDispersant R.I.=1.3300) were used in all of the particle sizedistribution tests. 20% NaCl water solution with pH adjusted to 11.5.

[0067] Shale Inhibition Test

[0068] The shale inhibition characteristics were determined by shaledispersion tests that included static wafer test, and pore pressure(PPT) tests. In the PPT test, a preserved Pierre II shale core, 1 inchdiameter by 0.9 inch long (2.54 cm×2.29 cm long), is placed between twopistons, as described previously in Example 2. The circumference of theshale and pistons are sealed with a rubber sleeve. The plug is orientedwith the bedding planes in the parallel or high permeability direction.Drilling fluid at 300 psi (2,070 kPa) is displaced through the upstreampiston (borehole side) and seawater at 50 psi (345 kPa) is displacedthrough the downstream piston (formation side). The seawater in thedownstream piston is contained with a valve. As mud filtrate enters theborehole end of the plug, connate water in the shale is displaced intothe formation piston.

[0069] Latex Stability

[0070] As noted above, initial experiments indicated that some latexproducts (emulsion polymers) produced synergistic effects with analuminum complex, resulting in improved pore pressure transmissioncharacteristics of the fluids. This result revealed a new approach tothe design of highly inhibitive, water-based fluids. However, latex isgenerally considered to be a metastable system. The large surface of theparticles is thermodynamically unstable and any perturbation affectingthe balancing forces stabilizing the polymer dispersion results in achange in the kinetics of particle agglomeration. Most commerciallattices, which are designed for the production of synthetic rubber orthe application of painting/coating, are sensitive to increasingelectrolytic concentration and temperature.

[0071] As shown in Table I, among 16 latex samples tested in 26% and 20%NaCl solutions, none of them is stable in 26% NaCl and only AIRFLEX728and GENCAL7463 are relatively stable in 20% NaCl. Clearly, forsuccessful applications of latex in drilling fluids, latex stability inhigh salt environments and at elevated temperatures must be improved. Acommon technique used to increase latex stability in electrolytesolutions is the addition of some surfactants. FIG. 2 compares theeffect of EXP-152 on the particle size distributions of AIRFLEX728 withthat of GENCAL7463. These results indicate that a blend of GENCAL 7463and EXP-152 may be a stable product for drilling fluid applications.TABLE I Stability Test for Latex Products in NaCl Solution StabilityAfter 16 Hours Static Aging Tg 26% NaCl/3 lb/bbl 20% NaCl/3 lb/bbl Ex.Latex Samples (° C.) (8.58 g/l) NaAlO₂ (8.58 g/l) NaAlO₂ VinylAcetate/Ethylene Vinyl Chloride 7 AIRFLEX 728  0 Flocculation but pass100 mesh Flocculation/Coagulation Vinyl Acetate/Ethylene 8 AIRFLEX 426 0 Flocculation/Coagulation Flocculation/Coagulation 9 AIRFLEX 7200  0Flocculation/Coagulation Flocculation/Coagulation 10 VINAC XX-211 N/AFlocculation/Coagulation Flocculation/Coagulation 11 ELVACE 40722-00 N/AFlocculation/Coagulation Flocculation/Coagulation CarboxylatedStyrene/Butadiene 12 GENCAL 7463  13 Flocculation but pass 100 meshFloc. at 150° F. (66° C.) but stable at 75° F. (24° C.) 13 GENCAL 7470N/A Flocculation/Coagulation — 14 GENFLO 576 N/AFlocculation/Coagulation — 15 TYLAC 68219 N/A Flocculation but pass 100mesh Flocculation but pass 100 mesh 16 TYLAC CPS 812 N/AFlocculation/Coagulation — 17 TYCHEM 68710 N/A Flocculation/Coagulation— 18 ROVENE 9410 −56 Coagulation Coagulation 19 ROVENE 6140 −27Coagulation Coagulation Carboxylated Acrylic Copolymer 20 SYNTHEMUL CPSN/A Flocculation/Coagulation — 401 21 SYNTHEMUL N/AFlocculation/Coagulation — 97982 Styrene/Butadiene 22 ROVENE 4823L −51Coagulation Coagulation

[0072] Aluminum Complex

[0073] Although a synergistic effect of ALPLEX with latex on stabilizingshales was confirmed by PPT test results, this system is fragile andvery sensitive to increasing salt concentration and temperature. It wasfound that in 20% NaCl solution, 3% AIRFLEX728 or 3% GENCAL 7463 wereflocculated in a few minutes by adding 4 lb/bbl (11.4 g/l) ALPLEX.Prehydration of ALPLEX in fresh water or addition of some surfactant(e.g. EXP-152) did improve the stability of this system at lowtemperatures, but the latex particle size was still greatly influencedby ALPLEX. Those particles greater than 100 microns in the fluidcontaining ALPLEX may have partially resulted from insoluble lignite (acomponent of ALPLEX). A similar effect was also observed with GENCAL7463. Poor solubility and slow dissolution rate of the lignite in highsalt concentrations is probably the main factor contributing todecreased latex stability.

[0074] In order to find a polymer resin that was compatible with a latexsystem additional tests were performed. FIG. 3 shows the effects ofdifferent polymer resins on the particle size distributions of EXP-155.Among the tested samples, EXP-153 exhibited the best compatibility withthis latex system.

[0075] A new aluminum complex product, EXP-154 (a blend of 45% NaAlO₂,45% EXP-153 and 10% sodium D-gluconate) was invented for the latexsystem. FIG. 4 compares the effects on the mud properties for EXP-154with ALPLEX in 12 lb/gal (1.44 kg/l) 20% NaCl/NEW-DRILL/EXP-155 fluids.The experimental aluminum complex exhibits improved compatibility withlatex and biopolymers. Additionally, EXP-154 is found to controlfiltration, both API and HTHP, better than does ALPLEX.

[0076] Pore Pressure Transmission Testing

[0077] Borehole stability effects of the experimental latex system wereevaluated with the pore pressure transmission (PPT) tester previouslydescribed. A preserved Pierre II shale plug, 1 inch diameter by 0.9 inchlong (2.54 cm×2.29 cm long), is placed between two pistons, as describedpreviously in Example 2. The circumference of the shale and pistonssealed with a rubber sleeve. The plug is oriented with the beddingplanes in the parallel or high permeability direction. Drilling fluid at300 psi (2,070 kPa) is displaced through the upstream piston (boreholeside) and seawater at 50 psi (345 kPa) is displaced through thedownstream piston (formation side). The seawater in the downstreampiston is contained with a valve. As mud filtrate enters the boreholeend of the plug, connate water in the shale is displaced into theformation piston. This additional water compresses the water inside thepiston causing the pressure to rise. The pressure increase in theformation piston water is measured as formation pressure (FP) rise.

[0078] The EXP-154/EXP-155 fluid produces the best PPT results to dateas shown in FIG. 5. The top curve is a standard salt/polymer. The nextone down is ALPLEX, the next curve is an EXP-154/AIRFLEX 728formulation, below that is the EXP-154/EXP-155 formulation, and finallyat the bottom is a 80/20 ISOTEQ fluid, 25% CaCl₂, 6 ppb (17.2 g/l)CARBO-GEL, and 10 ppb (28.6 g/l) OMNI-MUL. Without necessarily beinglimited to one explanation, the superior performance of theEXP-154/EXP-155 fluid is believed to be due, at least in part, to itssmall particle size. As discussed previously, GENCAL 7463 was moreefficiently dispersed by the EXP-152 resulting in a much greaterpercentage of particles smaller than one micron.

[0079] A synergistic effect between latex and aluminum complex has alsobeen observed in these tests. Such results may be related to theco-precipitation behavior of EXP-155 and EXP-154. It was found thatEXP-154 becomes insoluble at pH <10. At this condition, EXP-155 alonedoes not precipitate. However, when EXP-154 exists in this system,EXP-155 will be co-precipitated with EXP-154. Because of theirco-precipitation behavior, deposited particles on the shale surface arecomprised of lipophilic and hydrophilic components. This multiphasesystem is capable of creating a semi-permeable membrane, resulting in agreat improvement in osmotic efficiency. Another characteristic ofEXP-155 is that its ultra-fine particles are elastomer-like over a widerange of temperatures. When subjected to differential hydraulicpressure, these ultra-fine particles do not shear or break, but deformand penetrate the hairline fractures and to form an impermeable seal. Atthe temperatures between T_(g) (glass transition temperature) and T_(m)(melting point), most polymers will exhibit rubber-like elasticity. Theglass transition temperature of EXP-155 is 52° F. (11° C.). From therelationship between T_(g) and T_(m) plotted by Boyer, 1963, reproducedin Billmeyer, Textbook of Polymer Science, Second Edition,Wiley-Interscience, New York, 1971, p.230, we can estimate that T_(m) ofEXP-155 is about 300° F. (422° K). This temperature range covers mostapplications in drilling fluids.

[0080] Circulation of the fluid was found to be an important element ofthe latex plugging mechanism. This was explored in the tests withEXP-155. As the formulation was only 1.5% latex particles by volume(EXP-155 is 50% active), insufficient latex was available in the mud toproduce plugging under static conditions. With circulation, however, thelatex accumulated on the surface and formed a plugging film. Standardprocedure is to circulate the mud about 7 hours followed by staticexposure overnight. Four or five hours without circulation elapsesbefore the test is started in the morning. This static period eliminatespressure drift due to temperature effects by allowing temperaturevariation from circulation to equilibrium.

[0081] When the test started the formation pressure fell from 50 psi(345 kPa) to zero, increasing the differential pressure from 250 to 300psi (1,720 to 2,070 kPa), as seen in FIG. 6. In about 30 hours, the plugbegan to leak and the formation pressure rose. However, additionalcirculation sealed the leak in an hour and the pressure again fell tozero. In previous tests the circulation was stopped after an hour, andthe plug started leaking again after another 30 hours. In this test,circulation was restarted after the pressure rose to 60 psi (414 kPa) in70 hours (FIG. 6). However, circulation was maintained 5 hours insteadof one as before. With a few hours of continued circulation after thegreater pressure differential was established, the seal was more stable.The pressure rose only a few psi in 45 hours.

[0082] Photomicrographs of the plug face showed latex accumulation alongmicrofractures in the shale. As the volume and velocity of filtrationflow into these cracks is very small, filtration alone cannot accountfor the latex accumulation at the crack throat. Inside these cracks theclay surface area to filtrate volume ratio is very large resulting inheavy EXP-154 precipitation. The reason may relate to theco-precipitation behavior of EXP-154 and EXP-155 as discussed previous,without being limited to any particular explanation. The precipitationof aluminum complex at pH<19 apparently enhances latex accumulation atthe crack throat. When sufficient latex is deposited to bridge the crackopening, the fracture is sealed and differential pressure is establishedacross the latex. The differential pressure consolidates the latexdeposit into a solid seal. Increasing the differential pressureapparently causes this seal to deform over time (about 30 hours in thecase of the FIG. 6 results) and/or grows additional cracks in the shaleand the shale begins to leak, although the inventors do not necessarilywant to be limited by this explanation. However, additional circulationrapidly sealed the leaks and reestablished the seal. Circulating afterthe full differential pressure was reached formed a stable seal withonly a small pressure rise.

[0083] Eff ct of Lat x n Mud Pr perties

[0084] The previous results and discussions deal with latex stability indrilling fluids and its synergy with aluminum complex in improving mudinhabitability to shale formations. Besides, improved performanceparameters achieved by the latex products were also recognized. Twolatex samples, Latex A (8:1 blended AIRFLEX 728 and EXP-152) and EXP-155(8:1 blended GENCAL 7463 and EXP-152), were evaluated in 9.6 lb/gal(1.15 kg/l) 20% NaCl and 12 lb/gal (1.44 kg/) 20% NaCl fluids. Theeffects of adding 3% by volume of these latex products are illustratedin FIGS. 7 and 8. Without obvious effect on the fluid rheology, HTHPfluid loss at 250° F. (121° C.) decreased as much as 45% and 52% in 9.6lb/gal (1.15 kg/l) mud and 35% and 40% in 12 lb/gal (1.44 kg/l) mud byLatex A and EXP-155, respectively. Again, EXP-155 presents betterresults that AIRFLEX 728. Additional tests with EXP-155 are listed inTable II. TABLE II Typical Performance Parameters of 12 lb/gal 20%NaCl/EXP-155 Fluids Formulation Example # 23 24 Water, bbl (I) 0.89 0.89(141) XAN-PLEX D, lb/bbl (g/l) 0.5 (1.43 g/l) 0.5 (1.43 g/l) BIO-PAQ,lb/bbl (g/l) 4 (11.4) — BIO-LOSE, lb/bbl (g/l) — 4 (11.4) NEW DRILLPLUS, lb/bbl (g/l) 1 (2.86) 1 (2.86) EXP-154, lb/bbl (g/l) 5 5 (14.3)NaCl, lb/bbl (g/l) 77.5 (222) 77.5 (222) EXP-155, % by vol. 3 3 MIL-BAR,lb/unweighted bbl 150 (429) 150 (429) (g/l) Rev-Dust, lb/bbl (g/l) 27(77.2) 27 (77.2) Initial Properties PV, cP 22 21 YP, lb/100 ft² 26 (179)20 (138) 10 sec. gel, lb/100 ft² (kPa) 5 (34) 4 (28) 10 min. gel, lb/100ft² (kPa) 10 (69) 8 (56) API, cm³/30 min 2.5 1.4 pH 10.6 10.7 Density,lb/gal 12.2 12.2 after HR 16 hr @ 150° F. 250° F. — 150° F. 250° F. —(66° C.) (121° C.) (66° C.) (121° C.) after static aged 16 hr @ — — 300°F. — — 300° F. (149° C.) (149° C.) PV, cP 20 21 22 26 24 23 YP, lb/100ft² (kPa) 24 (165) 29 (200) 34 (234) 17 (117) 21 (145) 22 (152) 10 sec.gel, lb/100 ft² (kPa)  6 (41)  7 (48) 10 (69)  4 (28)  5 (34)  5 (34) 10min. gel, lb/100 ft² (kPa)  9 (62) 10 (69) 13 (90)  7 (48)  7 (48)  7(48) API, ml  2.8  3.7  2.8  2.2  2.6  1.8 pH 10.4  9.7  9.7 10.5  9.710.1 HTHP fluid loss, cm³/30 min.  9.4 16.4 12  8.4 13 10.8

[0085] Toxicity Test

[0086] The 96 hour range-finder bioassay results of AIRFLEX 728, GENCAL7463, EXP-152, EXP-154 and EXP-155 in 12 lb/gal (1.44 kg/l) 20%NaCl/NEW-DRILL fluids are presented in FIG. 9. All products meet therequirement for fluid disposal in the Gulf of Mexico (30,000 ppm) andbecome less toxic after solids contamination.

EXAMPLE 7

[0087] Because latex polymers contain deformable colloidal particles, itcan provide an excellent bridging and sealing ability to reduce thepermeability of the formation where the lost circulation of drillingfluids may encountered. Table III shows a typical formulation fortesting the sealing ability of latex polymers on permeable formation.Without latex polymer, the fluid loss of this mud is out control.However, an addition of 3% of a vinyl acetate/ethylene/vinyl chloridelatex polymer, available under the trade designation Airflex 728, intothis mud results in the fluid loss decreasing sharply with time as shownin FIG. 10. Tables IV-VI display the data for FIG. 10.

[0088]FIG. 11 shows the section picture of a broken 50 milliDarcy (mD)disk after testing for four hours at 300° F. with the fluid containing3% latex polymer. DFE-245 is an admixture of GenCal 7463 and MirataineBET-O30 at a volume ratio of about 9:1. It can be clearly observed thatthe internal filter cake was formed inside of the 50 mD disk. TABLE IIIMud Formulation for Testing Latex effect on High Pressure Fluid LossFormulation # 1094-52-1 Water, bbl 0.89 NEW-DRILL ® PLUS, lb/bbl 0.4MIL-PAC LV, lb/bbl 2 MAX-PLEX, lb/bbl 4 NaCl, lb/bbl 77.5 Airflex 728(latex polymer), % by vol. 3 Maritaine BET-O30, lb/bbl 1

[0089] TABLE IV High Temperature High Pressure Fluid loss at 500 psi and75° F. on 50 mD disk for the mud containing 3% Airflex 728 Timeinterval, HPHT FL, Average rate of HPHT minutes ml FL, ml/minutes 0-14.5 4.50  1-10 2 0.22 10-30 1.5 0.08 30-60 1.5 0.05  60-120 2.5 0.04

[0090] TABLE V High Temperature High Pressure Fluid loss at 500 psi and250° F. on 50 mD disk for the mud containing 3% Airflex 728 Timeinterval, HPHT FL, Average rate of HPHT minutes ml FL, ml/minutes 0-1 66.00  1-10 4 0.44 10-30 6 0.30 30-60 4 0.13  60-120 4 0.07

[0091] TABLE VI High Temperature High Pressure Fluid loss at 500 psi and300° F. on 50 mD disk for the mud containing 3% Airflex 728 Timeinterval, HPHT FL, Average rate of HPHT minutes ml FL, ml/minutes 0-1 1010  1-10 13 1.44 10-30 8 0.4 30-60 6 0.20  60-120 10 0.17 120-180 5 0.08

[0092] In the foregoing specification, the invention has been describedwith reference to specific embodiments thereof, and has beendemonstrated as effective in providing a water-based drilling fluid thatcan effectively reduce the rate of drilling fluid pressure invasion ofthe borehole wall. However, it will be evident that variousmodifications and changes can be made thereto without departing from thebroader spirit or scope of the invention as set forth in the appendedclaims. Accordingly, the specification is to be regarded in anillustrative rather than a restrictive sense. For example, specificcombinations of brines and latexes and with precipitating agents and/orwetting surfactants or salts falling within the claimed parameters, butnot specifically identified or tried in a particular composition toreduce mud pressure penetration into shale, sand, and otherformations,are anticipated to be within the scope of this invention. GLOSSARY4025-70 Low molecular weight amphoteric polymer sold by Amoco, found tobe ineffective (also abbreviated as 4025). AIRFLEX 728 Apolyvinylacetate latex (more specifically, an ethylenevinyl chloridevinylacetate copolymer) dispersion sold by Air Products. AIRFLEX 426Vinyl acetate/ethylene copolymer available from Air Products. AIRFLEX7200 Vinyl acetate/ethylene copolymer available from Air Products.ALPLEX ® Proprietary aluminum complex product available from BakerHughes INTEQ. AqS Abbreviation for AQUACOL-S, a glycol available fromBaker Hughes INTEQ. BIO-LOSE Derivatized starch available from BakerHughes INTEQ. BIOPAQ Derivatized starch fluid loss additive availablefrom Baker Hughes INTEQ. CARBO-GEL An amine-treated clay marketed byBaker Hughes INTEQ. CARBO-MUL Invert emulsion emulsifier marketed byBaker Hughes INTEQ. ELVACE 40722-00 Vinylacetate/ethylene copolymerlatex available from Reichhold. EXP-152 Oleamidopropyl betainesurfactant. EXP-153 Sulfonated polymer resin (or sulfonated humic acidwith resin) available from Baker Hughes INTEQ. EXP-154 A mixture of 45%NaAlO₂, 45% EXP-153 and 10% sodium D- gluconate. EXP-155 An 8:1 volumeblend of GENCAL 7463 and EXP-152. FLOWZAN Biopolymer available fromDrilling Specialties. FT-1 A SULFATROL, 90% water-soluble sulfatedasphalt dispersion sold by Baker Hughes INTEQ. GENCAL 7463 Carboxylatedstyrene/butadiene available from Omnova Solution Inc. GENCAL 7470Carboxylated styrene/butadiene available from Omnova Solution Inc.GENFLO 576 Available from Omnova Solution Inc. LD8 A commercial defoameravailable from Baker Hughes INTEQ. LIGCO Lignite sold by Baker HughesINTEQ. MIL-BAR Barite weighting agent available from Baker Hughes INTEQ.MIL-CARB Calcium carbonate weighting agent available from Baker HughesINTEQ. MILPAC LV Low viscosity polyanionic cellulose available fromBaker Hughes INTEQ (sometimes abbreviated as PacLV). MAX-PLEX Analuminum complex for shale stability available from Baker Hughes INTEQ.MIRATAINE BET-O-30 Betaine surfactant from Rhodia NEWDRILL PLUSPartially hydrolyzed polyacrylamide available from Baker Hughes INTEQ.ROVENE 4823L Styrene/butadiene copolymer available from Mallard Creek.ROVENE 6140 Carboxylated styrene/butadiene available from Mallard Creek.ROVENE 9410 Carboxylated styrene/butadiene available from Mallard Creek.SA Abbreviation for sodium aluminate. SYNTHEMUL 97982 Carboxylatedacrylic copolymer available from Reichhold. SYNTHEMUL CPS 401Carboxylated acrylic copolymer available from Reichhold. TYCHEM 68710Carboxylated styrene/butadiene copolymer available from Reichhold. TYLAC68219 Carboxylated styrene/butadiene copolymer available from Reichhold.TYLAC OPS 812 Carboxylated styrene/butadiene copolymer available fromReichhold. VINAC XX-211 Vinyl acetate/ethylene copolymer available AirProducts. XAN-PLEX D Biopolymer available from Baker Hughes INTEQ.

We claim:
 1. A water-based drilling fluid comprising: a) a polymer latexcapable of providing a deformable latex film on at least a portion of asubterranean formation; and b) water.
 2. The water-based drilling fluidof claim 1 where the water comprises salt.
 3. The water-based drillingfluid of claim 1 further comprising a precipitating agent.
 4. Thewater-based drilling fluid of claim 1 further comprising a surfactant.5. A water-based drilling fluid comprising: a) a polymer latex; b) aprecipitating agent; and c) water.
 6. The water-based drilling fluid ofclaim 5 where the water comprises salt and is a saturated salt brine. 7.The water-based drilling fluid of claim 5 further comprising asurfactant.
 8. A water-based drilling fluid comprising: a) a polymerlatex; b) a precipitating agent; c) a surfactant; and d) water.
 9. Thewater-based drilling fluid of claim 8 where the water comprises salt.10. The water-based drilling fluid of claim 9 where the salt in thesaturated salt brine is selected from the group consisting of calciumchloride, sodium chloride, potassium chloride, magnesium chloride,calcium bromide, sodium bromide, potassium bromide, calcium nitrate,sodium formate, potassium formate, cesium formate, and mixtures thereof.11. The water-based drilling fluid of claim 8 where the polymer latex iscapable of providing a deformable latex seal on at least a portion of asubterranean formation and is selected from the group consisting ofpolymethyl methacrylate, polyethylene, carboxylated styrene/butadienecopolymer, polyvinylacetate copolymer, polyvinyl acetate/vinylchloride/ethylene copolymer, polyvinyl acetate/ethylene copolymer,natural latex, polyisoprene, polydimethylsiloxane, and mixtures thereof.12. The water-based drilling fluid of claim 8 where the precipitatingagent is selected from the group consisting of silicates, aluminumcomplexes, and mixtures thereof.
 13. The water-based drilling fluid ofclaim 8 where the surfactant is selected from the group consisting ofbetaines, alkali metal alkylene acetates, sultaines, ether carboxylates,and mixtures thereof.
 14. The water-based drilling fluid of claim 8where the polymer latex is present in the drilling fluid in an amount offrom about 0.1 to about 10 volume % based on the total water-baseddrilling fluid.
 15. The water-based drilling fluid of claim 8 where theprecipitating agent is present in the drilling fluid in an amount offrom about 0.25 to about 20 lb/bbl based on the total water-baseddrilling fluid.
 16. The water-based drilling fluid of claim, 8 where thesurfactant is present in the drilling fluid in an amount of from about0.005 to about 2 wt. % based on the total water-based drilling fluid.17. The water-based drilling fluid of claim 9 where the salt is presentin the drilling fluid in an amount of from about 1 wt. % to aboutsaturation based on the total water-based drilling fluid.
 18. Thewater-based drilling fluid of claim 8 where polymer latex comprisesparticles that average less than 1 micron in size.
 19. A water-baseddrilling fluid comprising: a) from about 1 to about 10 volume % of apolymer latex selected from the group consisting of polymethylmethacrylate, polyethylene, carboxylated styrene/butadiene copolymer,sulfonated styrene/butadiene copolymer, polyvinylacetate copolymer,polyvinyl acetate/vinyl chloride/ethylene copolymer, polyvinylacetate/ethylene copolymer, natural latex, polyisoprene,polydimethylsiloxane, and mixtures thereof; b) from about 0.25 to about20 lb/bbl of a precipitating agent selected from the group consisting ofsilicates, aluminum complexes, and mixtures thereof; c) at least 1 wt. %of a salt selected from the group consisting of calcium chloride, sodiumchloride, potassium chloride, magnesium chloride, calcium bromide,sodium bromide, potassium bromide, calcium nitrate, sodium formate,potassium formate, cesium formate, and mixtures thereof; d) from about0.005 to about 2 vol. % of a surfactant selected from the groupconsisting of betaines, alkali metal alkylene acetates, sultaines, ethercarboxylates, and mixtures thereof; and e) water making up the balance,where the proportions are based on the total water-based drilling fluid.20. A method of inhibiting borehole wall invasion when drilling with awater-based drilling fluid in a subterranean formation, the methodcomprising: a) providing a water-based drilling fluid comprising: i) apolymer latex capable of providing a deformable latex seal on at least aportion of a subterranean formation; and ii) water; and b) circulatingthe water-based drilling fluid in contact with a borehole wall.
 21. Themethod of claim 20 where in providing the water-based drilling fluid,the water comprises salt.
 22. The method of claim 20 where in providingthe water-based drilling fluid, the fluid further comprises aprecipitating agent.
 23. The method of claim 20 where in providing thewater-based drilling fluid, the fluid further comprises a surfactant.24. A method of inhibiting borehole wall invasion when drilling with awater-based drilling fluid in a subterranean formation, the methodcomprising: a) providing a water-based drilling fluid comprising: i) apolymer latex; ii) a precipitating agent; and iii) water; and b)circulating the water-based drilling fluid in contact with a boreholewall.
 25. The method of claim 24 where in providing the water-baseddrilling fluid, the water comprises salt and is a saturated salt brine.26. The method of claim 24 where in providing the water-based drillingfluid, the water-based drilling fluid further comprises a surfactant.27. A method of inhibiting borehole wall invasion when drilling with awater-based drilling fluid in a subterranean formation, the methodcomprising: a) providing a water-based drilling fluid comprising: i) apolymer latex; ii) a precipitating agent; iii) a surfactant; and iv)water; and b) circulating the water-based drilling fluid in contact witha borehole wall.
 28. The method of claim 27 where in providing thewater-based drilling fluid, the water comprises salt.
 29. The method ofclaim 28, where the salt is selected from the group consisting ofcalcium chloride, sodium chloride, potassium chloride, magnesiumchloride, calcium bromide, sodium bromide, potassium bromide, calciumnitrate, sodium formate, potassium formate, cesium formate, and mixturesthereof.
 30. The method of claim 27, where in providing the water-baseddrilling fluid, the polymer latex is capable of providing a deformablelatex seal on at least a portion of a subterranean formation and isselected from the group consisting of polymethyl methacrylate,polyethylene, carboxylated styrene/butadiene copolymer, polyvinylacetatecopolymer, polyvinyl acetate/vinyl chloride/ethylene copolymer,polyvinyl acetate/ethylene copolymer, natural latex, polyisoprene,polydimethylsiloxane, and mixtures thereof.
 31. The method of claim 27where in providing the water-based drilling fluid, the precipitatingagent is selected from the group consisting of silicates, aluminumcomplexes, and mixtures thereof.
 32. The method of claim 27 where inproviding the water-based drilling fluid, the surfactant is selectedfrom the group consisting of betaines, alkali metal alkylene acetates,sultaines, ether carboxylates, and mixtures thereof.
 33. The method ofclaim 27 where in providing the water-based drilling fluid, the polymerlatex is present in the drilling fluid in an amount of from about 0.1 toabout 10 vol. % based on the total water-based drilling fluid.
 34. Themethod of claim 27 where in providing the water-based drilling fluid,the precipitating agent is present in the drilling fluid in an amount offrom about 0.25 to about 20 lb/bbl based on the total water-baseddrilling fluid.
 35. The method of claim 27 where in providing thewater-based drilling fluid, the surfactant is present in the drillingfluid in an amount of from about 0.005 to about 2 vol. % based on thetotal water-based drilling fluid.
 36. The method of claim 28 where thesalt is present in the drilling fluid in an amount of from about 1 wt. %to about saturation based on the total water-based drilling fluid. 37.The method of claim 27 where in providing the water-based drillingfluid, the polymer latex comprises particles that average less than 1micron in size.
 38. A method of inhibiting borehole wall invasion whendrilling with a water-based drilling fluid in a subterranean formation,the method comprising: a) providing a water-based drilling fluidcomprising: i) from about 0.1 to about 10 vol. % of a polymer latexselected from the group consisting of polymethyl methacrylate,polyethylene, carboxylated styrene/butadiene copolymer, sulfonatedstyrene/butadiene copolymer, polyvinylacetate copolymer, polyvinylacetate/vinyl chloride/ethylene copolymer, polyvinyl acetate/ethylenecopolymer, natural latex, polyisoprene, polydimethylsiloxane, andmixtures thereof; ii) from about 0.25 to about 20 lb/bbl of aprecipitating agent selected from the group consisting of silicates,aluminum complexes, ether carboxylates, and mixtures thereof; iii) atleast 1 wt. % of a salt selected from the group consisting of calciumchloride, sodium chloride, potassium chloride, magnesium chloride,calcium bromide, sodium bromide, potassium bromide, calcium nitrate,sodium formate, potassium formate, cesium formate, and mixtures thereof;iv) from about 0.005 to about 2 vol. % of a surfactant selected from thegroup consisting of betaines, alkali metal alkylene acetates, sultaines,ether carboxylates, and mixtures thereof; and v) water making up thebalance, where the proportions are based on the total water-baseddrilling fluid; and b) circulating the water-based drilling fluid incontact with a borehole wall.
 39. A water-based drilling fluidcomprising: a) from about 1 to about 10 volume % of a sulfonatedstyrene/butadiene copolymer latex; b) from about 0.25 to about 20 lb/bblof a precipitating agent selected from the group consisting ofsilicates, aluminum complexes, and mixtures thereof; and c) water makingup the balance, where the proportions are based on the total water-baseddrilling fluid.
 40. A method of inhibiting borehole wall invasion whendrilling with a water-based drilling fluid in a subterranean formation,the method comprising: a) providing a water-based drilling fluidcomprising: i) from about 0.1 to about 10 vol. % of a sulfonatedstyrene/butadiene copolymer; ii) from about 0.25 to about 20 lb/bbl of aprecipitating agent selected from the group consisting of silicates,aluminum complexes, ether carboxylates, and mixtures thereof; and iii)water making up the balance, where the proportions are based on thetotal water-based drilling fluid; and b) circulating the water-baseddrilling fluid in contact with a borehole wall.
 41. The method of claim40 wherein the drilling fluid is being used to stabilize shale or reducedrilling fluid loss while drilling in depleted sands.
 42. A method ofinhibiting borehole wall invasion when drilling with a water-baseddrilling fluid in a subterranean formation to reduce drilling fluid losswhile drilling in depleted sands, the method comprising: a) providing awater-based drilling fluid comprising: i) from about 0.1 to about 10vol. % of a sulfonated styrene/butadiene copolymer; and ii) water makingup the balance, where the proportions are based on the total water-baseddrilling fluid; and b) circulating the water-based drilling fluid incontact with a borehole wall.
 43. A method of inhibiting borehole wallinvasion when drilling with a water-based drilling fluid in asubterranean formation to reduce drilling fluid loss while drilling indepleted sands, the method comprising: a) providing a water-baseddrilling fluid comprising: i) from about 0.1 to about 10 vol. % of acarboxylated styrene/butadiene copolymer; ii) from about 0.005 to about2 vol. % of a surfactant selected from the group consisting of betaines,alkali metal alkylene acetates, sultaines, ether carboxylates, andmixtures thereof; and water making up the balance, where the proportionsare based on the total water-based drilling fluid; and b) circulatingthe water-based drilling fluid in contact with a borehole wall.